Reservoir fluid viscosity and permeability are two parameters that can be used for a) estimating technically recoverable and commercially developable oil and/or gas volumes, b) forecasting production, and/or c) managing oil and/or gas reservoirs. A relatively high permeability alone does not always facilitate a high flow rate from a reservoir, since fluid viscosity also has significant influence. In general, the combination of high permeability and low fluid viscosity ensure optimal flow rate.
The oil and gas industry has two main conventional methods for determining oil or gas viscosity. One method for determining oil or gas viscosity is the wireline formation tester (WFT) method. Another method for determining oil or gas viscosity is the nuclear magnetic resonance (NMR) logging method. The WFT method determines oil viscosity in the laboratory by pressure-volume-temperature (PVT) oil samples obtained by wireline formation tester, which provides a relatively accurate oil viscosity. However, the WFT method is expensive and time consuming The NMR logging method determines oil viscosity based on the NMR T2 value of oil and/or NMR porosity deficit, and provides a viscosity curve relatively soon after logging. However, the NMR method is less accurate than the WFT method, and requires that a calibration be performed based on viscosity measurements of oil samples from a wireline formation tester, i.e. using the WFT method.
The determination of reservoir fluid viscosity is often challenging even with oil samples from wireline formation tester (WFT) and NMR data. This is especially true in carbonate reservoirs.
In many cases, oil samples and/or NMR data are not available. However, at the present time, there are no methods or systems for determining a viscosity of a fluid (e.g., oil, gas, etc.) in a rock without WFT samples or NMR data.